Distributed hydrogen extraction system

ABSTRACT

A hydrogen extraction system is provided. The extraction system can comprise a compressor for compressing a gas mixture comprising hydrogen and a desulfurization unit for receiving the compressed gas mixture. The system can also comprise a hydrogen-extraction device for receiving a reduced-sulfur gas mixture and a hydrogen storage device for receiving an extracted hydrogen gas. A method of extracting hydrogen from a gas mixture comprising natural gas and hydrogen, and a method of determining an energy price are also provided.

This application claims priority to U.S. Provisional Application No.61/675,041, filed Jul. 24, 2012, which is incorporated herein byreference in its entirety.

This disclosure is generally directed to a system for distributedhydrogen extraction.

Some energy sources are currently distributed by networks, while otherenergy sources are delivered in bulk and stored on-site. For example,electrical and some gas networks use power lines and pipelines to supplyenergy to residential households and commercial operations. Whereas oiland some other gases are delivered by truck to on-site storagefacilities. However, changing regulations, environmental considerations,and economic factors will affect future distribution of energy sources.

Hydrogen gas is typically distributed using tankers and stored in largetanks on-site or at specific distribution centers. Another hydrogendistribution system could use an existing gas network, where hydrogen isadded to a transport gas for distribution via the existing network.Extraction systems coupled to the network could extract hydrogen fromthe transport gas as required, reducing transportation and storagecosts.

One proposed method of hydrogen distribution uses a natural gas (NG) ora synthetic NG (SNG) network. Up to 50% hydrogen can be added to an NGnetwork without significantly affecting typical consumers of NG. Someproposals include adding about 10% to about 20% hydrogen to existing NGnetworks. Hydrogen can be produced, either renewably or from fossilfuels, and added to an existing NG network where it can be distributedto a number of consumers. Multiple hydrogen extraction systems could becoupled to the existing network and configured to extract hydrogen asrequired.

Current hydrogen generation systems are not suitable for use with thenetwork described above for several reasons. Most current hydrogengeneration systems are configured for industrial-scale operation and arenot suitable for small-scale use. They can be large, expensive, complexto operate, or require extensive maintenance.

The present disclosure is directed to overcoming one or more of thedisadvantages of existing hydrogen generation systems. Moreover,hydrogen produced by the extraction systems described herein can bestored on site, supplied to a dedicated hydrogen distribution system, orused on site. For example, the extracted hydrogen could be supplied to afuel cell and used to produce electricity.

Other aspects of the present disclosure are directed to monitoring andpricing hydrogen gas usage. For example, as hydrogen gas will likelyhave a greater value than NG, monitoring hydrogen gas consumptionseparately from NG consumption will more accurately account for theactual cost of gas consumed. This may also affect the monetization ofblended fuel. The present disclosure describes systems and methods tomonitor both hydrogen and NG consumption at the point of use.

One aspect of the present disclosure is directed to a hydrogenextraction system. The extraction system can comprise a compressor forcompressing a gas mixture comprising hydrogen and a desulfurization unitfor receiving the compressed gas mixture. The system can also comprise ahydrogen-extraction device for receiving a reduced-sulfur gas mixtureand a hydrogen storage device for receiving an extracted hydrogen gas.

Another aspect of the present disclosure is directed to a method ofextracting hydrogen from a gas mixture comprising natural gas andhydrogen. The method can comprise compressing the gas mixture andremoving at least part of the sulfur contained in the compressed gasmixture to form a sulfur-rich stream and a reduced-sulfur mixture. Themethod can also comprise removing at least part of the hydrogencontained in the reduced-sulfur mixture to form a hydrogen-depletedmixture and a hydrogen gas and supplying the hydrogen gas to a hydrogenstorage device or other use.

Another aspect of the present disclosure is directed to a method ofdetermining an energy price. The method can comprise a) determining amass flow rate of hydrogen gas and b) determining a mass flow rate ofnatural gas. The method can also comprise c) multiplying the mass flowrate of hydrogen gas by a factor for hydrogen gas, d) multiplying themass flow rate of natural gas by a factor for natural gas, and e) addingthe values of step c) and step d).

Additional objects and advantages of the present disclosure will be setforth in part in the description which follows, and in part will beobvious from the description, or may be learned by practice of thepresent disclosure. The objects and advantages of the present disclosurewill be realized and attained by means of the elements and combinationsparticularly pointed out in the appended claims.

It is to be understood that both the foregoing general description andthe following detailed description are exemplary and explanatory onlyand are not restrictive of the systems, devices, and methods, asclaimed.

The accompanying drawings, which are incorporated in and constitute apart of this specification, illustrate several embodiments of thepresent disclosure and together with the description, serve to explainthe principles of the present disclosure.

FIG. 1 is a schematic representation of a hydrogen distribution system,according to an exemplary embodiment.

FIG. 2 is a schematic representation of a hydrogen extraction system,according to an exemplary embodiment.

FIG. 3 is a schematic representation of another hydrogen extractionsystem, according to another exemplary embodiment.

FIG. 4 is a schematic representation of the hydrogen extraction systemof FIG. 3, according to another exemplary embodiment.

FIG. 5A is a schematic representation of a monitoring system, accordingto an exemplary embodiment.

FIG. 5B is a schematic representation of the monitoring system of FIG.5A, according to another exemplary embodiment

FIG. 5C is a schematic representation of the monitoring system of FIG.5A, according to another exemplary embodiment.

Reference will now be made in detail to the exemplary embodiments of thepresent disclosure, examples of which are illustrated in theaccompanying drawings. Wherever possible, the same reference numberswill be used throughout the drawings to refer to the same or like parts.

FIG. 1 is a schematic representation of a hydrogen distribution system10, according to an exemplary disclosed embodiment. Hydrogendistribution system 10 can comprise a network 20 for distribution of afluid to various locations. Network 20 can be designed to transport amixture of various liquids or gasses, or a single type of liquid or gas.For example, network 20 can comprise an existing gas distributionsystem.

Various pipelines, conduits, passageways, and other fluid transportationdevices and systems can form at least part of network 20. Network 20 canalso comprise various devices (not shown) designed for fluid handling.These devices can comprise storage facilities, pumping stations, valves,filters, meters, control systems, monitoring systems, or other equipmentused in conjunction with fluid or gas transfer.

In some embodiments, network 20 can comprise a natural gas distributionsystem that supplies natural gas (NG) to residential or commercialsites. NG can include a mixture of several gas species. Network 20 cancomprise a pipeline 30 configured to receive various fluids, includingNG. In addition, a hydrogen source 40 can be fluidly connected topipeline 30 to supply network 20 with hydrogen.

Hydrogen source 40 can comprise a steam reformer (not shown) or otherdevice configured to produce hydrogen. The steam reformer could besupplied with electricity, water, and NG from pipeline 30. Electricitycould be supplied by conventional or alternate energy sources, such as,wind or solar energy. The steam reformer may comprise a large reformer(e.g., >2000 kg/day), injecting hydrogen into a high flow or a highpressure pipeline at centralized nodes. Some industrial reformers mayproduce up to about 600 tonnes of hydrogen each day. In otherembodiments, the steam reformer may comprise a small reformer (e.g., <5kg/day) located at a user's home. Other steam reformers at any scalebetween large and small may also be used.

Other sources of hydrogen could comprise systems or methods used togenerate hydrogen via electrolysis of water using electricity, renewablyelectricity (wind, solar, geothermal), non-renewable electricity (coal,oil, gas, nuclear), biological production, water splitting by directsolar catalysis, or wastewater treatment.

Multiple hydrogen sources 40 could be located throughout network 20 andconfigured to supply hydrogen to pipeline 30 where needed. In someembodiments, a gas mixture 60 within pipeline 30 can be greater than 80%NG and less than 20% hydrogen. Gas mixture 60 can also comprise lessthan 5% hydrogen and less than 10% hydrogen. Gas mixture 60 could, insome instances, contain up to 75% hydrogen. It is also contemplated thatnetwork 20 may comprise a dedicated system for distribution of gasmixture 60 having about 100% hydrogen. In addition, one or more hydrogenextraction systems 70 may be coupled to network 20.

FIG. 2 is a schematic representation of hydrogen extraction system (HES)70, according to an exemplary disclosed embodiment. HES 70 may beconfigured to extract hydrogen from gas mixture 60. In some embodiments,HES 70 may comprise cost-effective system for the separation,purification, and/or compression of hydrogen gas. Given a relativelysmall number of components, HES 70 may be configured to occupy a smallvolume and/or a small footprint. As such, HES 70 could be used inresidential or small-scale commercial applications.

For example, HES 70 could be configured to supply hydrogen at about 0.5kg/day for one fuel cell electric vehicle (FCEV) or about 1 kg/day fortwo FCEVs. Hydrogen gas may then be compressed to a pressure of betweenabout 350 to about 700 bara, as may be required for on-board storage ina FCEV. HES 70 could be sized to provide hydrogen at a rate required fora fleet of more than two FCEVs. In other examples, HES 70 could beconfigured to supply to a fuel cell for stationary electricityproduction, such as about 4 kg/day (e.g., residence), about 25 kg/day(e.g., apartment complex), about 50 kg/day (e.g., industrial building),or about 250 kg/day (e.g., large manufacturing or distribution center),or about 1,500 to about 2,500 kg/day (e.g., fuel cell car refueling atservice stations).

HES 70 can be fluidly coupled to pipeline 30 via a supply conduit 80. Asexplained below with regard to FIGS. 5A-5C, supply conduit 80 cancomprise a meter (400, but not shown in FIG. 2) to monitor a flow of gasmixture 60 from pipeline 30 to HES 70. Supply conduit 80 can be fluidlycoupled to a compressor 90 configured to compress a fluid. Compressor 90can include a pump, a blower, or another compression device suitable foroperation with natural gas. In some embodiments, compressor 90 may onlypump a fluid and may not need to compress the fluid. In particular,compressor 90 can be configured to pump a fluid mixture through at leastpart of HES 70. If HES 70 comprises a low pressure drop, compressor 90could operate as a blower.

Output from compressor 90 can be directed into a desulfurization unit100 configured to remove at least some sulfur from the fluid supplied todesulfurization unit 100. Various types desulfurization unit 100 mayoperate with HES 70. For example, desulfurization unit 100 can comprisea regenerative thermal swing adsorption (TSA) type. The TSA may beconfigured so that the sulfur removed from the stream leavingdesulfurization unit 100 can be added back into a stream returning topipeline 30. Such a configuration may require little or no maintenance,such as, for example, replacement of a desulfurization catalyst.

In some embodiments, HES 70 may not include compressor 90. For example,gas mixture 60 may be supplied to desulfurization unit 100 directly frompipeline 30 at sufficient pressure. In particular, gas mixture 60 couldbe supplied at about 100 to about 1,000 psig. At such pressures, orhigher, gas mixture 60 may require no additional pressurization beforebeing directed into desulfurization unit 100.

Following at least partial removal of sulfur from the fluid bydesulfurization unit 100, a supply of reduced-sulfur gas mixture outputby desulfurization unit 100 can be directed to a hydrogen extractionunit 110 to extract hydrogen. Extracted hydrogen gas output by hydrogenextraction unit 110 can be stored in one or more storage vessels 130.

In some embodiments, hydrogen extraction unit 110 can comprise anelectrochemical stack (EHC) 120, or similar device, configured toseparate, purify, and/or compress hydrogen. EHC 120 may be configured toprovide a simpler and more cost-effective system than some other formsof extraction unit 110. For example, EHC 120 may have no moving parts orless components than other forms of extraction unit 110. In addition,EHC 120 may have lower noise or a smaller footprint than apressure-swing absorber system.

In some embodiments, heat output by EHC 120 can be supplied todesulfurization unit 100 or another component of hydrogen extractionsystem 70. This heat can be used to drive a thermal regeneration processfor a TSA-based desulfurization unit 100 described above.

The reduced-hydrogen fluid mixture output by hydrogen extraction unit110 can be supplied back to desulfurization unit 100. Withindesulfurization unit 100, the reduced-hydrogen fluid mixture can berecombined with the sulfur extracted by desulfurization unit 100. Theresulting fluid can be feed back into pipeline 30 or used at the site ifdesired.

FIG. 3 is a schematic representation of another hydrogen extractionsystem (HES) 170, according to another exemplary disclosed embodiment.Similar to the embodiment described above, HES 170 can comprise acompressor 190 and a desulfurization unit 200. For example,hydrogen-enriched natural gas can be compressed by compressor 190 andsupplied to a selective membrane device 180. Selective membrane device180 can be selective for hydrogen, and may be used to increase hydrogenconcentration of a fluid to greater than 50% by volume.

Selective membrane device 180 can be used to separate hydrogen based onthe difference in hydrogen partial pressure between a feed side and apermeate side. Selective membrane device 180 can comprise a membrane185, wherein membrane 185 can comprise a dense polymer membrane ofvarious forms, including hollow fiber bundle, spiral wound, or flatsheets. Such membranes are commercially available from specializedsupplies, such as Air Products, BOC, or Air Liquide. Selective membranedevice 180 can also comprise an inorganic hydrogen selective membrane.

Fluid output from selective membrane device 180 can be supplied todesulfurization unit 200 as described above. In other embodiments, HES170 lacks desulfurization unit 200. Output from selective membranedevice 180 can be supplied directly to a pressure swing absorption (PSA)device 210.

PSA 210 can be used to further purify the permeate stream from selectivemembrane device 180 to increase hydrogen purity to greater than 90%,greater than 95%, or greater than 99%. PSA 210 can employ multipleabsorption beds and piping networks to connect the beds. The absorbent(not shown) can be in bead form or a structured form. Rotary valve,rotary beds, rapid-cycle PSA, or other devices known in the art may alsobe used.

FIG. 4 is a schematic representation of another hydrogen extractionsystem (HES) 270, according to another exemplary disclosed embodiment.Similar to the embodiments described above, HES 270 can comprise acompressor 290 and a desulfurization unit 300. Hydrogen-enriched fluidcan be compressed by compressor 290 and supplied to desulfurization unit300.

Desulfurization unit 300 can comprise a multi-bed desulfurizerconfigured to at least partially remove sulfur-species from the gasmixture stream before the gas mixture is fed into a selective membranedevice 280. Some beds within desulfurization unit 300 can be operated inan adsorption mode and other beds can be operated in a regenerationmode. Desorbed sulfur-species can be carried back to pipeline 30 using afraction of returning gas output from selective membrane device 280and/or a pressure swing absorption (PSA) device 310 similar to describedabove. As shown in FIG. 4, fluid output from selective membrane device280 can be supplied to PSA 310. In other embodiments, various componentsof HES 70, 170, 270 can be differently configured to receive fluid fromor supply fluid to other components.

FIG. 5A-C show various configurations of a monitoring system 390,according to some exemplary embodiments. Monitoring system 390 can beconfigured to monitor a flow of hydrogen gas mixture. Various electroniccomponents (not shown) can be associated with system 390, such as, forexample, a processor, memory, communication systems, etc. Monitoringsystem 390 can also comprise a meter 400 fluidly coupled to pipeline 30and configured to receive a supply of gas mixture from pipeline 30.Meter 400 can also be coupled to a hydrogen extraction system (HES) 470.

While meter 400 is shown in FIGS. 5A-C, various other devices or methodscan be used to determine flow rate. For example, meter 400 couldcomprise a traditional flow meter or a totalizer. In other embodiments,one or more components of HES 470 could be used to monitor a flow rateof one or more gases input or output from HES 470.

As explained above, hydrogen extracted from HES 470 could be stored onsite, or used to supply hydrogen to a fuel cell 410 or a hydrogendistribution network (not shown). Hydrogen-depleted natural gas outputfrom HES 470 could be supplied to a natural gas (NG) unit 420. NG unit420 could comprise various residential or commercial devices configuredto operate with NG, such as, for example, a heat source. In someembodiments, hydrogen or NG output from HES 470 can be returned topipeline 30. In other embodiments, EHC 120 could be used to determinehydrogen flow.

Hydrogen will likely be more valuable than the NG used to transport it.Consequently, a user would prefer being charged based on how muchhydrogen or NG they consume rather than paying for the entire gasmixture if they only consume part of it. Different prices for energyconsumption can be determined based on a user's consumption of either NGor hydrogen.

FIG. 5A shows a scenario where a consumer extracts both NG and hydrogengas from a gas mixture supplied by pipeline 30. For example, NG can besupplied to NG unit 420 and hydrogen gas can be supplied to fuel cell410. A monetary value can be determined based on analyzing various fluidflows, such as, input and output flows. The calculations listed belowcan also be modified to include various permutations of one or moreflows.

The price charged to the consumer for the scenario shown in FIG. 5A canbe the sum of two or more calculations, or an equivalent determination.For example, each calculation can be proportional to the energy consumedtimes the market value for that energy form. The following equation(Equation 1) can be used to determine an energy price:Energy Price=V _(H) ₂ ×{dot over (m)} _(H) ₂ +V _(NG)×(cfm−{dot over(m)} _(H) ₂ )wherein, V_(H) ₂ represents a market value factor for hydrogen gas, {dotover (m)}_(H) ₂ represents a mass flow rate of hydrogen gas, V_(NG)represents a market value factor for NG, and cfm represents a total massflow reading from meter 400.

FIG. 5B shows a scenario where a consumer extracts only hydrogen gasfrom a gas mixture supplied by pipeline 30 and returns all the NG topipeline 30. As explained above, the price charged to the consumer canbe the sum of two or more calculations. The first calculation can beproportional to the energy consumed times the market value of thehydrogen. The second calculation can be proportional to the energy valuedepletion due to the return of NG to pipeline 30. The following equation(Equation 2) can be used to determine an energy price:Energy Price=V _(H) ₂ ×{dot over (m)} _(H) ₂ +F _(depletion)×(cfm−{dotover (m)} _(H) ₂ )wherein, F_(depletion) represents a factor to account for the valuedepleted from the NG network by the consumer's extraction of hydrogengas and the other variables are as described above for Equation 1.

FIG. 5C shows a scenario where a consumer extracts only NG from a gasmixture supplied by pipeline 30 and returns all the hydrogen gas topipeline 30. The price charged to the consumer can be the differencebetween two calculations. The first calculation can be proportional tothe energy consumed times the market value for NG. The secondcalculation can be proportional to the energy value addition due to thereturn of the hydrogen gas to pipeline 30. The following equation(Equation 3) can be used to determine an energy price:Energy Price=V _(H) ₂ ×(cfm−{dot over (m)} _(H) ₂ )−F _(addition) ×{dotover (m)} _(H) ₂wherein, F_(addition) represents a factor to account for the value addedto the NG network by the consumer's return of hydrogen gas and the othervariables are as described above for Equation 1.

Other embodiments of the present disclosure will be apparent to thoseskilled in the art from consideration of the specification and practiceof the concepts disclosed herein. For example, another type of gas orfluid, other than NG, may be used with the above disclosure. Moreover,one or more functions or components of above systems may be combinedinto a single unit. Further, different equations or algorithms may beused that use different parameters to those described above, but usesimilar concepts or principles. It is intended that the specificationand examples be considered as exemplary only, with a true scope andspirit of the present disclosure being indicated by the followingclaims.

What is claimed is:
 1. A hydrogen extraction system, comprising: acompressor configured to compress a gas mixture comprising hydrogen andoutput a compressed gas mixture; a selective membrane device configuredto receive the compressed gas mixture from the compressor, wherein theselective membrane device includes a hydrogen selective membrane thatincreases a hydrogen concentration of the compressed gas mixture; adesulfurization unit configured to receive the compressed gas mixturefrom the selective membrane device and remove at least a portion ofsulfur contained in the compressed gas mixture and output areduced-sulfur gas mixture; a hydrogen-extraction device configured toreceive the reduced-sulfur gas mixture and extract at least part of thehydrogen and output the extracted hydrogen gas; and a hydrogen storagedevice configured to receive the extracted hydrogen gas.
 2. The systemof claim 1, wherein the hydrogen extraction system is fluidly coupled toa network supplying a gas mixture comprising natural gas and hydrogengas.
 3. The system of claim 2, wherein the desulfurization unit furtherreceives a supply of reduced-sulfur gas mixture from thehydrogen-extraction device following removal of at least part of thehydrogen from the reduced-sulfur gas mixture, combines the supply ofreduced-sulfur gas mixture with sulfur removed from the compressed gasmixture, and returns the combined gas mixture to the network.
 4. Thesystem of claim 1, wherein the hydrogen-extraction device comprises apressure swing adsorption device.
 5. The system of claim 1, wherein theselective membrane device increases the hydrogen concentration of thecompressed gas mixture to greater than 50% by volume.
 6. The system ofclaim 1, wherein the hydrogen-extraction device comprises anelectrochemical stack.
 7. The system of claim 6, wherein theelectrochemical stack is configured to at least partially purify andcompress the extracted hydrogen gas.
 8. The system of claim 1, furtherincluding a fuel cell for receiving the extracted hydrogen gas andgenerating electricity.